The following descriptions and examples do not constitute an admission as prior art by virtue of their inclusion within this section.
Oilfield operations, such as surveying, drilling, wireline testing, completions, production, planning and oilfield analysis, are typically performed to locate and gather valuable downhole fluids. During the oilfield operations, data is typically collected for analysis and/or monitoring of the oilfield operations. Such data may include, for example, subterranean formation, equipment, historical and/or other data. Such formation data may be static or dynamic. Static data relates to, for example, formation structure and geological stratigraphy that define geological structures of the subterranean formation. Dynamic data relates to, for example, fluids flowing through the geologic structures of the subterranean formation over time. Such static and/or dynamic data may be collected to learn more about the formations and the valuable assets contained therein.
Sensors may be positioned about the oilfield to collect data relating to various oilfield operations. For example, sensors in the drilling equipment may monitor drilling conditions, sensors in the wellbore may monitor fluid composition, sensors located along the flow path may monitor flow rates and sensors at the processing facility may monitor fluids collected. Other sensors may be provided to monitor downhole, surface, equipment or other conditions. Such conditions may relate to the type of equipment at the wellsite, the operating setup, formation parameters or other variables of the oilfield. The monitored data is often used to make decisions at various locations of the oilfield at various times. Data collected by these sensors may be further analyzed and processed. Data may be collected and used for current or future operations. When used for future operations at the same or other locations, such data may sometimes be referred to as historical data.
The data may be used to predict downhole conditions, and make decisions concerning oilfield operations. Such decisions may involve well planning, well targeting, well completions, operating levels, production rates and other operations and/or operating parameters. Often this information is used to determine when to drill new wells, re-complete existing wells or alter wellbore production. Oilfield conditions, such as geological, geophysical, and reservoir engineering characteristics, may have an impact on oilfield operations, such as risk analysis, economic valuation, and mechanical considerations for the production of subsurface reservoirs. Data from one or more wellbores may be analyzed to plan or predict various outcomes at a given wellbore. In some cases, the data from neighboring wellbores, or wellbores with similar conditions or equipment, may be used to predict how a well will perform. There are usually a large number of variables and large quantities of data to consider in analyzing oilfield operations. It is, therefore, often useful to model the behavior of the oilfield operation to determine a desired course of action. During the ongoing operations, the operating parameters may be adjusted as oilfield conditions change and new information is received.
Techniques have been developed to enhance the production of oilfield from subterranean formations. One such technique involves the use of gas-lifted wells. Gas lift is an artificial-lift method in which gas is injected into the production tubing to reduce the hydrostatic pressure of the fluid column. The resulting reduction in bottomhole pressure allows the reservoir liquids to enter the wellbore at a higher flowrate. The injection gas is typically conveyed down the tubing-casing annulus and enters the production train through a series of gas lift valves. Various parameters for performing the gas lift operation (i.e., lift configuration), such as gas lift valve position, operating pressures and gas injection rate, may be determined by specific well conditions. The injected gas (or lift gas) is provided to reduce the bottom-hole pressure and allow more oil to flow into the wellbore. While the discussion below refers to lift gas, one skilled in the art will appreciate that any resource (e.g., gas, energy for electrical submersible pump (ESP) lifted well, stimulation agents such as methanol, choke orifice size, etc.) may be used to provide or enhance lift.
There are many factors to consider in designing a gas lift operation. The optimal conditions for performing a gas lift operation may depend on a variety of factors, such as the amount of lift gas to inject, inflow performance, equipment (e.g. tubing), surface hydraulics, operating constraints, cost, handling capacities, compression requirements and the availability of lift gas. Moreover, a gas lift well network (i.e., a network including gathering network and at least one gas lift well) may be constrained by the amount of gas available for injection or at other times the total amount of produced gas permissible during production due to separator constraints. Under either of these constraints, engineers may allocate the lift gas amongst the wells so as to maximize the oil production rate. This is an example of a real world scenario that can be modeled in network simulators. For example, a gathering network model may be used to allocate the amount of lift gas to inject into each well based on static boundary conditions at the reservoir and processing facility. Other methods of increasing production in oilfields may involve allocation of electrical power to electrical submersible pump (ESP) lifted wells or allocation of chemicals to wells stimulated by chemical injection, etc. Throughout this document, the use of the term “lift gas” or “gas lift” should include any possible resource that could provide lift and not be limited to merely include the use of gas.